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| United States Patent |
5,082,057
|
|
Sydansk
|
January 21, 1992
|
Sand consolidation treatment for a hydrocarbon production well bore
using an overdisplacement fluid
Abstract
A process is provided for sand consolidation treatment in a subterranean
hydrocarbon-bearing formation in fluid communication with a hydrocarbon
production well bore. An immature flowing gel is injected through the well
bore into a treatment zone of the formation and followed by an
overdisplacement fluid which displaces a portion of the immature gel from
the zone. Displacement of a portion of the immature gel from the zone
establishes flow pathways through the zone for subsequent hydrocarbon
production while the gel remaining in the zone matures and effectively
consolidates the sand therein.
| Inventors:
|
Sydansk; Robert D. (Littleton, CO)
|
| Assignee:
|
Marathon Oil Company (Findlay, OH)
|
| Appl. No.:
|
627689 |
| Filed:
|
December 14, 1990 |
| Current U.S. Class: |
166/295; 166/294; 166/300 |
| Intern'l Class: |
E21B 033/138 |
| Field of Search: |
166/291,292,294,295,300
523/131
|
References Cited
U.S. Patent Documents
| 2378817 | Jun., 1945 | Wrightsman.
| |
| 2476015 | Jul., 1949 | Wrightsman et al.
| |
| 2604172 | Jul., 1952 | Wrightsman.
| |
| 2823753 | Feb., 1958 | Henderson et al.
| |
| 2981334 | Apr., 1961 | Powell et al.
| |
| 3123138 | Mar., 1964 | Robichaux | 166/295.
|
| 3189091 | Jun., 1965 | Bearden et al. | 166/295.
|
| 3306356 | Feb., 1967 | Sparlin | 166/295.
|
| 3334689 | Aug., 1967 | McLaughlin | 166/295.
|
| 3339633 | Sep., 1967 | Richardson | 166/295.
|
| 3421584 | Jan., 1969 | Eilers et al. | 166/295.
|
| 3476189 | Nov., 1969 | Bezemer et al. | 166/295.
|
| 3800847 | Apr., 1974 | Rike | 166/295.
|
| 3978928 | Sep., 1976 | Clampitt | 166/294.
|
| 4193453 | Mar., 1980 | Golinkin | 166/295.
|
| 4216829 | Aug., 1980 | Murphey | 166/295.
|
| 4427069 | Jan., 1984 | Friedman | 166/295.
|
| 4512407 | Apr., 1985 | Friedman | 166/295.
|
| 4665987 | May., 1987 | Sandiford et al. | 166/295.
|
| 4683949 | Aug., 1987 | Sydansk et al. | 166/270.
|
| 4688639 | Aug., 1987 | Falk | 166/295.
|
| 4903770 | Feb., 1990 | Friedman et al. | 166/288.
|
| Foreign Patent Documents |
| 2099886 | Dec., 1982 | GB.
| |
Other References
Chapter 56, Petroleum Engineering Handbook, H. B. Bradley, Editor-in-Chief,
Society of Petroleum Engineers, Richardson, Texas (1987).
|
Primary Examiner: Suchfield; George A.
Attorney, Agent or Firm: Hummel; Jack L., Ebel; Jack E.
Claims
I claim:
1. A process for consolidating sand in a treatment zone of a subterranean
hydrocarbon-bearing formation in fluid communication with a well bore
comprising:
admixing an acrylamide-containing polymer, a transition metal
cation-containing crosslinking agent and an aqueous solvent at the surface
to form an aqueous immature flowing gel;
injecting said immature flowing gel into said treatment zone of said
formation via said well bore, said immature gel thereby occupying a volume
in said treatment zone;
injecting a hydrocarbon overdisplacement fluid substantially immiscible in
said aqueous immature flowing gel into said treatment zone to displace a
portion of said aqueous immature flowing gel out of said treatment zone,
said overdisplacement fluid thereby occupying the fraction of said volume
in said treatment zone vacated by said displaced portion of said aqueous
immature flowing gel;
shutting in said well bore for a time sufficient for said aqueous immature
flowing gel remaining in said treatment zone to mature to a non-flowing
gel, thereby consolidating said sand in said treatment zone; and
producing hydrocarbons from said formation through the fraction of said
volume occupied by said overdisplacement fluid in said treatment zone into
said well bore.
2. The process of claim 1 wherein said acrylamide-containing polymer is
selected from the group consisting of polyacrylamide, partially hydrolyzed
polyacrylamide, copolymers of acrylamide and acrylate, and
carboxylate-containing terpolymers and tetrapolymers of acrylate.
3. The process of claim 1 wherein said metal cation is trivalent chromium.
4. The process of claim 1 wherein said overdisplacement fluid is a
hydrocarbon liquid.
5. The process of claim 1 wherein the mobility ratio of said immature
flowing gel and said overdisplacement fluid is between about 0.3 and 150.
6. The process of claim 1 wherein said overdisplacement fluid displaces
said immature gel substantially to residual saturation in said treatment
zone.
7. The process of claim 1 wherein said overdisplacement fluid is less
viscous than said immature flowing gel.
8. A process for consolidating sand in a treatment zone of a subterranean
hydrocarbon-bearing formation in fluid communication with a well bore
comprising:
injecting an aqueous immature flowing gel into said treatment zone of said
formation via said well bore, wherein said gel comprises an
acrylamide-containing polymer and a metal cation-containing crosslinking
agent;
injecting a hydrocarbon liquid substantially immiscible with said aqueous
immature flowing gel into said treatment zone to displace a portion of
said aqueous immature flowing gel out of said treatment zone;
shutting in said well bore for a time sufficient for said aqueous immature
flowing gel remaining in said treatment zone to mature to a non-flowing
gel, thereby consolidating said sand in said treatment zone; and
producing hydrocarbons from said formation across said treatment zone and
into said well bore.
Description
BACKGROUND OF THE INVENTION
The invention relates to a process for recovering hydrocarbons from a
subterranean hydrocarbon-bearing formation and more particularly to a sand
consolidation treatment process for a well bore penetrating a subterranean
hydrocarbon-bearing formation.
BACKGROUND INFORMATION
Technical Field
Sand control problems arise when a production well bore is drilled into a
formation containing unconsolidated or poorly cemented sand particles or
other mineral particles commonly found in sandstone formations, such as
clays, feldspars, and mica. Inadequate sand control results in the
production of such particles into the production well bore from the
hydrocarbon-bearing formation. Sand control problems are particularly
acute when large drawdown pressures are encountered.
The production of sand and other mineral particles into the well bore is
undesirable because a significant fraction of the particles often drop out
of the well bore fluids and settle at the bottom of the well bore. The
settled particles eventually build up to the producing interval if no
remedial action is undertaken. The accumulation of sand at the producing
interval reduces the hydrocarbon productivity of the well bore. The
particles entering the well bore which do not settle out are produced to
the surface. Their presence in the topside production equipment represents
a serious risk to the operation of the equipment.
Another negative consequence of sustained sand production is the potential
for collapse of the formation. The migration of sand from the formation
into the well bore leaves voids in the formation which expand and
ultimately collapse. The result can be diminished hydrocarbon productivity
from the formation.
A number of technologies exist for sand control. Gravel packing can be
effective for sand control, but a number of economic and operational
constraints are associated with gravel packing. Gravel packing is often
operationally or economically prohibitive to perform on already completed
well bores which consequently inhibits the use of gravel packing in many
existing well bores. Even in well bores being newly completed where gravel
packing is feasible, it is nevertheless relatively expensive, requiring
specialized hardware and know-how to properly place a gravel pack in the
well bore.
An alternative to gravel packing is the cementing of sand particles
together in situ, i.e., sand consolidation, to prevent sand production
into the well bore. Plastic resins having utility as cements for sand
consolidation treatments are described in U.S. Pat. Nos. 4,427,069;
4,512,407 and 4,903,770 as well as UK Patent No. 2,099,886. However, sand
consolidation treatments using resins are not entirely satisfactory.
Resins tend to reduce the permeability of the consolidated formation below
acceptable levels. In addition, resins are relatively costly on a unit
volume basis and can be operationally very difficult to properly place in
the formation. Resins also often contain toxic substances which in many
cases are environmentally undesirable.
Crosslinked gels have been substituted for resins as cements for sand
consolidation treatments. U.S. Pat. No. 3,978,928 discloses a process
employing a gel in sand consolidation treatments. However, as with resins,
gels tend to reduce the permeability and thus the hydrocarbon productivity
of the formation beyond acceptable levels.
As such, a sand consolidation treatment process is needed which overcomes
the problems of the above-described treatment processes known in the art.
Specifically, a sand consolidation treatment process is needed which is
relatively inexpensive, which is easily applied in relatively large
volumes, and which effectively promotes sand consolidation without
excessive permeability damage to the formation.
SUMMARY OF THE INVENTION
The present invention is a process for consolidating sand in a subterranean
hydrocarbon-bearing formation in fluid communication with well bore.
According to the process, an aqueous gelation solution is prepared. The
immature aqueous flowing gel which results from the gelation solution is
injected into the formation via the well bore. The immature gel is placed
in the desired treatment zone where it contacts the sand therein.
An overdisplacement fluid is injected into the formation behind the
immature gel slug which is preferably substantially immiscible with the
immature gel. The overdisplacement fluid displaces a portion of the
immature gel out of the treatment zone away from the well bore and
occupies the volume in the treatment zone vacated by the displaced gel. A
substantial volume of immature gel, however, is not displaced from the
treatment zone and remains therein. The well bore is shut in to enable the
remaining immature gel to reach maturity and consequently consolidate the
sand in the treatment zone.
After the shut-in time, hydrocarbon production is resumed in the well bore.
The hydrocarbons flow without substantial restriction through the
consolidated treatment zone into the well bore by displacing the
overdisplacement fluid residing in the treatment zone. No significant
amounts of sand are produced into the well bore after the consolidation
treatment, even under large drawdown pressures.
The process of the present invention overcomes the problems of known
treatment processes using sand consolidation cements because the present
process limits permeability damage in the treatment zone to acceptable
levels while effectively controlling sand production in the well bore. The
present sand consolidation treatment process is also in most cases
operationally simpler and more economical than conventional gravel packing
or resin treatments. Furthermore, unlike gravel packing, the present
process has general utility for remedial treatment of well bores which
have already been completed, as well as for new well bore completions.
DESCRIPTION OF PREFERRED EMBODIMENTS
The present invention is described below in the context of the following
terms. As used herein, the term "sand" refers broadly to silicon dioxide
particles as well as other migratable mineral particles which are found in
subterranean sandstone formations, such as clays, feldspars and mica.
As defined herein, "sand consolidation" is a treatment process which
renders sand in a subterranean formation substantially permanently fixed
in the formation and resistant to migration caused by internal or external
forces. Although the present invention is not limited to any particular
mechanism, sand consolidation is generally believed to be achieved by
cementing migratable sand particles to one another with a cementing
material which fills at least some of the interstices between the sand
particles. The cementing material in the interstices forms large clusters
of consolidated particles which are substantially incapable of migration
within the formation.
The term "gel" as used herein is directed to a continuous three-dimensional
crosslinked polymeric network which has a liquid occupying the interstices
of the network. The crosslinked polymeric network provides the gel
structure. The term "flowing gels" as used herein refers to gels which are
displaceable within the formation by an overdisplacement fluid while
"non-flowing gels" are essentially not displaceable in the formation by
the overdisplacement fluid, by other fluids injected into the formation,
or by fluids produced from the formation.
Gels are further characterized as either "mature" or "immature". A mature
gel is one in which crosslinking of the polymer by the crosslinking agent
has proceeded to substantial completion either because the crosslinking
agent or the crosslinking sites have been substantially consumed. An
immature gel is a gel in which crosslinking has not gone to completion
because a substantial quantity of available crosslinking sites and
crosslinking agent remain. The terms "crosslinking" and "gelation" are
used synonymously herein.
An "overdisplacement fluid" is defined as a fluid injected into a formation
via a well bore after injection of a treatment fluid which displaces at
least a portion of the treatment fluid away from the well bore.
The present invention is a process for sand consolidation in a subterranean
hydrocarbon-bearing formation employing an aqueous gel and an
overdisplacement fluid. The preferred gel of the present invention is a
crosslinked polymer gel comprising a crosslinkable polymer, a crosslinking
agent and an aqueous solvent.
The crosslinkable polymer is preferably a carboxylate-containing polymer
and more preferably an acrylamide-containing polymer. Of the
acrylamide-containing polymers, the most preferred are polyacrylamide
(PA), partially hydrolyzed polyacrylamide (PHPA), copolymers of acrylamide
and acrylate, and carboxylate-containing terpolymers and tetrapolymers of
acrylate. PA, having utility herein, has from about 0.1% to about 3% of
its amide groups hydrolyzed. PHPA, as defined herein, has greater than
about 3% of its amide groups hydrolyzed.
The crosslinking agent preferably effects crosslinking between the
carboxylate sites of the same or different polymer molecules within the
gel. Polymer crosslinking creates the network structure of the gel. The
crosslinking agent is preferably a molecule or complex containing a
reactive transition metal cation. A most preferred crosslinking agent
comprises trivalent chromium cations complexed or bonded to anions, atomic
oxygen or water. Exemplary crosslinking agents are compounds or complexes
containing chromic acetate (CrAc.sub.3) and/or chromic chloride
(CrCl.sub.3). Other transition metal cations which are found in
crosslinking agents having utility in the present invention, although less
preferred, are chromium VI within a redox system, aluminum III, iron II,
iron III and zirconium IV.
The aqueous gel may be prepared in any aqueous solvent in which the polymer
and crosslinking agent can be dissolved, mixed, suspended or otherwise
dispersed to facilitate gel formation. The solvent is preferably an
aqueous liquid such as distilled water, fresh water or a brine.
A number of the most preferred gels which have utility within the present
invention are taught in U.S. Pat. No. 4,683,949 which is incorporated
herein by reference.
The gel used in the present invention is formed by admixing the polymer,
crosslinking agent, and solvent at the surface in a gelation solution.
Surface admixing broadly encompasses inter alia mixing of the gel
components in bulk at the surface prior to injection or simultaneously
mixing the gel components at or near the wellhead by an in-line mixing
means while injecting them. Crosslinking is initiated in the gelation
solution as soon as the polymer and crosslinking agent contact, thereby
forming an immature gel. Crosslinking will proceed under favorable
conditions until the immature gel reaches maturity.
The present sand consolidation treatment process is practiced by preparing
the gelation solution in the manner described above and injecting a slug
of the resulting immature flowing gel into a desired treatment zone of the
formation via a hydrocarbon production well bore in fluid communication
therewith. The treatment zone is simply the region of the formation
wherein sand consolidation is desired, which is made up at least in part
of migratable sand particles attributable in most cases to either
unconsolidated or poorly cemented sandstone. The treatment zone is usually
in the near well bore environment, which is a volume extending radially up
about 10 meters or more from the well bore.
The injected flowing immature gel slug displaces much of the mobile fluids
occupying the interstitial volume of the sand particles in the desired
treatment zone. The mobile fluids typically include brines and
hydrocarbons. The result of the injection is a continuous slug of immature
flowing gel residing in the treatment zone, and specifically in the
interstitial volume thereof. The present process is generally applicable
to sand-containing formations and is particularly effective in water-wet
formations, wherein the injected immature gel not only occupies the
interstitial volume between the sand particles in the treatment zone, but
to a large degree simultaneously coats the sand particles therein.
An overdisplacement fluid is injected into the treatment zone following
injection of the immature gel while the immature gel is still in a flowing
state. An overdisplacement fluid is selected which has the ability to
sweep out a sufficient volume of immature flowing gel from the treatment
zone to restore acceptable permeability therein to produced hydrocarbons.
However, the sweeping ability of the overdisplacement fluid must not be so
great that insufficient gel is retained in the treatment zone for
effective sand consolidation.
A selection criterion which indicates the ability of the overdisplacement
fluid to satisfy the above-recited performance requirements is the
viscosity of the overdisplacement fluid relative to that of the initial
immature flowing gel. The overdisplacement fluid preferably has a
viscosity near that of the immature flowing gel and more preferably
somewhat less than that of the immature flowing gel. For a typical flowing
immature gel, the overdisplacement fluid preferably has a viscosity from
about 0.1 cp to about 1000 cp and more preferably from about 20 cp to
about 150 cp.
Another criterion used to select a satisfactory overdisplacement fluid is
the mobility ratio. The mobility ratio in the present fluid system, which
contains the immature flowing gel and the overdisplacement fluid, is
defined as the mobility of the aqueous immature flowing gel phase divided
by the mobility of the overdisplacement fluid. The mobility of a given
fluid is further defined as its permeability divided by its viscosity. A
preferred mobility ratio for the system is between about 0.1 and about 200
and more preferably between about 0.3 and about 150.
In addition to the criteria set forth above, the overdisplacement fluid is
preferably substantially immiscible and inert with the immature flowing
gel. Immiscible fluids are fluids which do not substantially mix upon
contact, but instead substantially remain in their discrete individual
phases. This property is particularly beneficial to the practice of the
present invention because immiscible displacement is an effective
mechanism for displacement of the immature gel from the treatment zone in
the manner described hereafter. More preferred overdisplacement fluids are
hydrophobic fluids and most preferably hydrocarbon liquids. Exemplary
preferred overdisplacement fluids satisfying these criteria include diesel
fuel and mineral oil.
The overdisplacement fluid is injected into the treatment zone in a manner
which displaces only a portion of the immature gel out of the treatment
zone and away from the producing well bore. The overdisplacement fluid
preferably drives the immature flowing gel to, or at least near, residual
saturation in the treatment zone. The displaced gel is dissipated out into
the formation where it has negligible negative impact on subsequent
hydrocarbon production into the well bore.
The portion of the flowing immature gel which is not displaced from the
treatment zone by the overdisplacement fluid remains in the treatment
zone. However, the gel slug is now traversed by one or more continuous
flow paths therethrough which are created and occupied by the
overdisplacement fluid fingering through the gel slug. Thus, the treatment
zone can be characterized as a plurality of sand particles having
interstices between the particles occupied by the immature gel and the
overdisplacement fluid. The fraction of the interstitial volume occupied
by the immature gel is the gel slug. The fraction of the interstitial
volume occupied by the overdisplacement fluid is the continuous flow paths
through the gel slug.
After injection of the overdisplacement fluid, the production well bore is
shut in for a time sufficient to enable the gel slug in the treatment zone
to crosslink to maturity. The resulting mature gel sets up in the fraction
of the interstitial volume it occupies. The overdisplacement fluid, which
remains in a flowing condition, continues to occupy its own fraction of
the interstitial volume.
Once the gel has set up, the well bore is returned to production.
Hydrocarbons from the outlying formation are freely produced into the well
bore across the treatment zone despite the presence of the non-flowing gel
slug therein because the interstitial volume occupied by the
overdisplacement fluid provides continuous pathways for the hydrocarbons.
The hydrocarbons simply displace the mobile overdisplacement fluid from
its occupied fraction of the interstitial volume as the hydrocarbons flow
therethrough under production drawdown pressure. At the same time the
mature gel has sufficient structure to resist displacement from its
fraction of the interstitial volume under the drawdown pressure.
Consequently the mature gel effectively consolidates the sand particles
therein to substantially prevent their migration and production into the
well bore.
The following example demonstrates the practice and utility of the present
invention, but is not to be construed as limiting the scope thereof.
EXAMPLE
A series of experimental runs are performed in a sandpack to simulate a
near well bore sand consolidation treatment. The sandpack is placed in a
constant low differential pressure test apparatus and flooded with fluids
according to the following procedure.
A 20-30 mesh, 120,000 md Ottawa sand is packed into a holder which is a
15.2 cm long tube having an inside diameter of 0.95 cm. Screens are fitted
at both ends of the tube which enable fluids to flow freely through the
tube, but prevent sand from escaping. The resulting sandpack is then
flooded with tap water to determine its initial permeability to tap water
(k.sub.i).
A gelation solution is prepared by combining partially hydrolyzed
polyacrylamide (PHPA) and chromic acetate in tap water. The PHPA is 3.0%
hydrolyzed and has a molecular weight of 500,000. The PHPA concentration
in the solution is 6.0 wt. %. The chromic acetate concentration is 6000
ppm. The gelation solution becomes an immature gel having an initial
viscosity of 520 cp.
A slug containing 3 pore volumes of the immature gel is injected into the
sandpack. Thereafter, a slug containing approximately 4 pore volumes of a
liquid hydrocarbon overdisplacement fluid, which is varied for each
experimental run, is injected into the sandpack. Both the gel slug and
overdisplacement fluid slug are injected at ambient temperature.
The sandpack is then aged at 60.degree. F. for 24 hours to accelerate
complete gelation. Tap water is again flooded through the sandpack and the
final permeability of the sandpack to the tap water (k.sub.f) is
calculated. The final permeability is compared to the initial permeability
to arrive at the value k.sub.f /k.sub.i, which indicates the degree of
permeability restoration in the sandpack upon completion of the treatment.
Finally the sandpack is cut open for visual inspection and the degree of
sand consolidation is qualitatively evaluated.
The results of the experiments are summarized in the table below.
TABLE
______________________________________
Initial Degree
Overdis- Fluid Gel of
Run placement Viscosity
Viscosity Consoli-
No. Fluid (cp) (cp) k.sub.f /k.sub.l
dation
______________________________________
1 n-Decane 0.9 520 0.003 Good
2 Mineral Oil
85 520 0.57 Good
3 30-wt 225 520 0.64 Marginal
Motor Oil
4 None -- 520 <1.1 .times. 10.sup.-5
Good
______________________________________
Of the three overdisplacement fluids, the mineral oil performed optimally
under the experimental conditions. Permeability restoration was
satisfactory and sand consolidation was good. Motor oil exhibited
excellent permeability restoration, but sand consolidation was not totally
satisfactory. Conversely, n-decane exhibited good sand consolidation, but
poor permeability restoration. The final run without the overdisplacement
step was performed as an experimental control and indicates almost no
permeability restoration, which would be expected.
It is apparent that selection of an appropriate overdisplacement fluid
enables one to effectively practice the process of the present invention.
An overdisplacement fluid is selected which has a high enough viscosity
and consequently a low enough mobility ratio to restore sufficient
permeability to the treatment zone, yet which does not have such a high
viscosity and correspondingly low mobility ratio that it sweeps too much
immature gel out of the treatment zone during the consolidation step.
Thus, an overdisplacement fluid is selected having a viscosity and
mobility ratio which strikes a balance between permeability restoration
and sand consolidation.
While the particular sand consolidation treatment process as herein shown
and disclosed in detail is fully capable of obtaining the objects and
providing the advantages herein before stated, it is to be understood that
it is merely illustrative of the presently preferred embodiments of the
invention and that no limitations are intended to the details of
construction or design herein shown other than as defined in the appended
claims.
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